Field of the Invention
The invention generally relates to methods of selecting drill bits.
Background Art
FIG. 1 shows one example of a conventional drilling system for drilling an earth formation. The drilling system includes a drilling rig 10 used to turn a drilling tool assembly 12 which extends downward into a wellbore 14. Drilling tool assembly 12 includes a drilling string 16, a bottom hole assembly (“BHA”) 18, and a drill bit 20, attached to the distal end of drill string 16.
Drill string 16 comprises several joints of drill pipe 16a connected end to end through tool joints 16b. Drill string 16 transmits drilling fluid (through its central bore) and transmits rotational power from drill rig 10 to BHA 18. In some cases drill string 16 further includes additional components such as subs, pup joints, etc. Drill pipe 16a provides a hydraulic passage through which drilling fluid is pumped. The drilling fluid discharges through selected-size orifices in the bit (“jets”) for the purposes of cooling the drill bit and lifting rock cuttings out of the wellbore as it is being drilled.
Bottom hole assembly 18 includes a drill bit 20. Typical BHAs may also include additional components attached between drill string 16 and drill bit 20. Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, and downhole motors.
In general, drilling tool assemblies 12 may include other drilling components and accessories, such as special valves, such as kelly cocks, blowout preventers, and safety valves. Additional components included in drilling tool assemblies 12 may be considered a part of drill string 16 or a part of BHA 18 depending on their locations in drilling tool assembly 12.
Drill bit 20 in BHA 18 may be any type of drill bit suitable for drilling earth formation. The most common types of earth boring bits used for drilling earth formations are fixed-cutter (or fixed-head) bits, roller cone bits, and percussion bits. FIG. 2 shows one example of a fixed-cutter bit. FIG. 3 shows one example of a roller cone bit.
Referring now to FIG. 2, fixed-cutter bits (also called drag bits) 21 typically comprise a bit body 22 having a threaded connection at one end 24 and a cutting head 26 formed at the other end. Cutting head 26 of fixed-cutter bit 21 typically comprises a plurality of ribs or blades 28 arranged about a rotational axis of the bit and extending radially outward from bit body 22. Cutting elements 29 are preferably embedded in the blades 28 to engage formation as bit 21 is rotated on a bottom surface of a wellbore. Cutting elements 29 of fixed-cutter bits may comprise polycrystalline diamond compacts (“PDC”), specially manufactured diamond cutters, or any other cutter elements known to those of ordinary skill in the art. These bits 21 are generally referred to as PDC bits.
Referring now to FIG. 3, a roller cone bit 30 typically comprises a bit body 32 having a threaded connection at one end 34 and one or more legs 31 extending from the other end. A roller cone 36 is mounted on a journal (not shown) on each leg 31 and is able to rotate with respect to bit body 32. On each cone 36, a plurality of cutting elements 38 are shown arranged in rows upon the surface of cone 36 to contact and cut a formation encountered by bit 30. Roller cone bit 30 is designed such that as it rotates, cones 36 of bit 30 roll on the bottom surface of the wellbore and cutting elements 38 engage the formation therebelow. In some cases, cutting elements 38 comprise milled steel teeth and in other cases, cutting elements 38 comprise hard metal inserts embedded in the cones. Typically, these inserts are tungsten carbide inserts or polycrystalline diamond compacts, but in some cases, hardfacing is applied to the surface of the cutting elements to improve wear resistance of the cutting structure.
Referring again to FIG. 1, for drill bit 20 to drill through formation, sufficient rotational moment and axial force must be applied to bit 20 to cause the cutting elements to cut into and/or crush formation as bit 20 is rotated. Axial force applied to bit 20 is typically referred to as the weight on bit (“WOB”). Additionally, the portion of the weight of drilling tool assembly 12 supported by a suspending mechanism of rig 10 is typically referred to as the hook load. Additionally, rotational moment can be provided by BHA components such as positive displacement motor or down hole turbines. Rotational moment applied to drilling tool assembly 12 by drill rig 10 (usually by a rotary table or a top drive) to turn drilling tool assembly 12 is referred to as the rotary torque. The speed at which drilling rig 10 rotates drilling tool assembly 12, typically measured in revolutions per minute (“RPM”), is referred to as the rotary speed.
The speed and economy with which a wellbore is drilled, as well as the quality of the hole drilled, depend on a number of factors. These factors include, among others, the mechanical properties of the rocks which are drilled, the diameter and type of the drill bit used, the flow rate of the drilling fluid, and the rotary speed and axial force applied to the drill bit. It is generally the case that for any particular mechanical property of a formation, a drill bit's rate of penetration (“ROP”) corresponds to the amount of axial force on and the rotary speed of the drill bit. The rate at which the drill bit wears out is generally related to the ROP. Various methods have been developed to optimize various drilling parameters to achieve various desirable results.
Prior art methods for optimizing values for drilling parameters that primarily involve looking at the formation have focused on the compressive strength of the rock being drilled. For example, U.S. Pat. No. 6,349,595, issued to Civolani, et al. (“the '595 patent”), and assigned to the assignee of the present invention, discloses a method of selecting a drill bit design parameter based on the compressive strength of the formation. The compressive strength of the formation may be directly measured by an indentation test performed on drill cuttings in the drilling fluid returns. The method may also be applied to determine the likely optimum drilling parameters such as hydraulic requirements, gauge protection, WOB, and the bit rotation rate. The '595 patent is hereby incorporated by reference in its entirety.
U.S. Pat. No. 6,424,919, issued to Moran, et al. (“the '919 patent”), and assigned to the assignee of the present invention, discloses a method of selecting a drill bit design parameter by inputting at least one property of a formation to be drilled into a trained Artificial Neural Network (“ANN”). The '919 patent also discloses that a trained ANN may be used to determine optimum drilling operating parameters for a selected drill bit design in a formation having particular properties. The ANN may be trained using data obtained from laboratory experimentation or from existing wells that have been drilled near the present well, such as an offset well. The '919 patent is hereby incorporated by reference in its entirety.
ANNs are a relatively new data processing mechanism. ANNs emulate the neuron interconnection architecture of the human brain to mimic the process of human thought. By using empirical pattern recognition, ANNs have been applied in many areas to provide sophisticated data processing solutions to complex and dynamic problems (i.e., classification, diagnosis, decision making, prediction, voice recognition, military target identification, to name a few).
Similar to the human brain's problem solving process, ANNs use information gained from previous experience and apply that information to new problems and/or situations. The ANN uses a “training experience” (i.e., the data set) to build a system of neural interconnects and weighted links between an input layer (i.e., independent variable), a hidden layer of neural interconnects, and an output layer (i.e., the dependant variables or the results). No existing model or known algorithmic relationship between these variables is required, but such relationships may be used to train the ANN. An initial determination for the output variables in the training exercise is compared with the actual values in a training data set. Differences are back-propagated through the ANN to adjust the weighting of the various neural interconnects, until the differences are reduced to the user's error specification. Due largely to the flexibility of the learning algorithm, non-linear dependencies between the input and output layers, can be “learned” from experience.
Several references disclose various methods for using ANNs to solve various drilling, production, and formation evaluation problems. These references include U.S. Pat. No. 6,044,325 issued to Chakravarthy, et al., U.S. Pat. No. 6,002,985 issued to Stephenson, et al., U.S. Pat. No. 6,021,377 issued to Dubinsky, et al., U.S. Pat. No. 5,730,234 issued to Putot, U.S. Pat. No. 6,012,015 issued to Tubel, and U.S. Pat. No. 5,812,068 issued to Wisler, et al, which are hereby incorporated by reference in their entirety. Methods of determining a bit type may include the use of a drilling optimization service. The drilling optimization service may identify rock type, strength, and porosity, as well as formation abrasion and potential impact from formation. The appropriate cutting structure may thereby be determined. One such service, called DBOS™, is offered by Smith International, Inc., the assignee of the entire right in the present application. The use of the drilling optimization service is disclosed in U.S. patent application Ser. No. 11/048,516, assigned to the assignee of the present invention, and hereby incorporated by reference in its entirety.
However, optimization predictions from these methods may not be as accurate as simulations of drilling, which may be better equipped to make predictions for each unique situation.
Simulation methods have been previously introduced which characterize either the interaction of a bit with the bottom hole surface of a wellbore or the dynamics of the BHA 18.
One simulation method for characterizing interaction between a roller cone bit and an earth formation is described in U.S. Pat. No. 6,516,293 (“the '293 patent”), entitled “Method for Simulating Drilling of Roller Cone Bits and its Application to Roller Cone Bit Design and Performance,” and assigned to the assignee of the present invention. The '293 patent discloses methods for predicting cutting element interaction with earth formations. Furthermore, the '293 patent discloses types of experimental tests that can be performed to obtain cutting element/formation interaction data. The '293 patent is hereby incorporated by reference in its entirety. Another simulation method for characterizing cutting element/formation interaction for a roller cone bit is described in Society of Petroleum Engineers (SPE) Paper No. 29922 by D. Ma et al., entitled, “The Computer Simulation of the Interaction Between Roller Bit and Rock”. A simulation method for simulating the dynamic response of a drilling tool assembly is disclosed in U.S. Pat. No. 6,785,641 (“the '641 patent”), entitled “Simulating the Dynamic Response of a Drilling Tool Assembly and its Application to Drilling Tool Assembly Design Optimization and Drilling Performance Optimization.” The '641 patent is hereby incorporated by reference in its entirety.
Similarly, U.S. patent application Ser. No. 10/888,523 (“the '523 application”) entitled “Methods for Designing Fixed Cutter Bits and Bits Made Using Such Methods,” and U.S. patent application Ser. No. 10/888,358 (“the '358 application”) entitled “Methods for Modeling, Displaying, Designing, and Optimizing Fixed Cutter Bits,” both assigned to the assignee of the present invention, disclose methods for modeling and simulating the performance of PDC bits. The '523 application and the '358 application disclose modeling and simulating by taking into account actual interactions between cutters and earth formations during drilling. U.S. patent application Ser. No. 10/888,354 (“the '354 application”) entitled “Methods for Modeling Wear of Fixed Cutter Bits and for Designing and Optimizing Fixed Cutter Bits,” and assigned to the assignee of the present invention, discloses a method for modeling and simulating the wear of PDC bits. The '354 application also takes into account actual interactions between cutters and earth formations during drilling. U.S. patent application Ser. No. 10/888,446 (“the '466 application”) entitled “Methods for Modeling, Designing, and Optimizing Drilling Tool Assemblies,” and assigned to the assignee of the present invention, discloses methods for modeling and simulating the dynamic response of a drilling tool assembly. The '523 application, the '358 application, the '354 application, and the '446 application are hereby incorporated by reference in their entirety.
In drilling a certain formation, one of the most important factors is the type of drill bit used. Thus, selecting the best drill bit is crucial. Even before drilling begins, a myriad of information may be available, including drilling parameters, well profile, and information on the drill string. What is needed is a streamlined method of selecting the best drill bit or bits based on the available information.